Distributed steam generation process for use in hydrocarbon recovery operations

ABSTRACT

A method and system for producing steam for use in heavy hydrocarbon recovery operations. In an arrangement with or without a central processing facility and/or a plurality of well pads in communication with the central processing facility, each well pad is provided with equipment for separation of materials produced from its respective wells, and steam generation equipment for that well pad, thus allowing for simplified piping transport.

CROSS REFERENCE TO RELATED APPLICATION

This application claims the benefit of and priority to U.S. Provisional Patent Application Ser. No. 62/050,908, filed Sep. 16, 2014, entitled “Distributed Steam Generation Process for Use in Hydrocarbon Recovery Operations,” the contents of which are incorporated herein in its entirety for all purposes.

FIELD OF THE INVENTION

The invention relates to thermal recovery methods and systems for heavy hydrocarbon deposits, and specifically to such methods and systems requiring steam injection to mobilize the deposits.

BACKGROUND

In the field of subsurface hydrocarbon production, it is known to employ various stimulation procedures and techniques to enhance production. For example, in the case of heavy oil and bitumen housed in subsurface reservoirs, conventional drive mechanisms may be inadequate to enable production to surface, and it is well known to therefore inject steam or steam-solvent mixtures to make the heavy hydrocarbon more amenable to movement within the reservoir permeability pathways, by heating the hydrocarbon and/or mixing it with lighter hydrocarbons or hot water.

In steam-assisted gravity drainage (“SAGD”) and cyclic steam stimulation (“CSS”) hydrocarbon recovery operations, steam is generated at surface by steam generation units and injected downhole into a well, where it is subsequently introduced into an underground hydrocarbon formation in which the well lies, after which the steam warms bitumen and oil within the formation. Thus-warmed hydrocarbon within the formation is mobilized and moves or is drawn toward the well, where it is then collected and produced to surface. The steam, when contacting cooler subterranean bitumen and oil, typically condenses to water, releasing latent heat of condensation and thereby effectively transferring heat to the oil/bitumen.

Due to the foregoing condensation of injected steam to water, and also by reason that underground formations typically contain amounts of water in the form of brine or the like, water is typically produced to surface with the recovered hydrocarbon. Because proximate sources of water for producing steam for injection downhole are often in very short supply, or their use prevented due to governmental restrictions, it is very desirable to use produced water to generate steam. Not only is such water (although contaminated) available at site, but by generating steam from produced water the disposal costs (which are also impacted by regulatory limitations) of such contaminated produced water is reduced.

Typically, water that is produced to surface with the collected hydrocarbon arrives in the form of free water and/or water-in-oil emulsions and/or oil-in-water reverse emulsions. The produced water must go through a series of processing steps to be useful as boiler feedwater, such as de-oiling, softening and ion exchange. Typical de-oiler systems include a free water knock out (“FWKO”) vessel, followed by a skim tank, induced gas floatation and finally an oil removal filter. The de-oiler system is conventionally used at surface to separate the recovered hydrocarbons from the produced water, and the produced water is thereafter recycled to the steam generation unit for re-use in converting same to steam for injection downhole; typically, however, the produced water contains significant impurities in the form of inorganic compounds, such as silica, calcium and magnesium ions, which must be addressed and controlled before the de-oiled produced water can be introduced to steam generation units as feedstock.

Conventional drum boilers operating at circa 2% blowdown cannot typically be used to generate steam from the produced water without the use of evaporators to generate high purity feedwater due to the concentration of impurities such as calcium, silica, organics and the like that cause precipitation and thereby scaling and fouling within boiler tubes during the boiling of the water, which thereby very quickly renders the boiler ineffective in transferring heat to the water to generate steam and can also rupture boiler tubes due to the generation of hot spots.

Alternatively, special types of steam generators are commonly used, namely so-called “once-through steam generators” (“OTSG” or “OTSGs”), which can better handle higher amounts of impurities in the produced water feed stream and generate steam ranging from 65% to 90% steam quality (10-35 parts water containing the impurities, 65-90 parts steam vapor). Operating at this steam quality greatly reduces the dissolved salts which foul and scale the tubes. Nevertheless, produced water pre-conditioning steps are still necessary, such as the warm lime softening (“WLS”) or hot lime softening (“HLS”) process, which injects lime to reduce water hardness and alkalinity and precipitates silica and carbonate ions out of the water, and in conjunction with a weak acid cation or strong acid cation ion exchange (“WACS” or “SACS”) process, removes the calcium and magnesium scale generating ions to acceptable concentrations, thereby reducing build-up of scale in the OTSG. The major bulk chemicals used in these processes are lime (Ca(OH)2), magnesium oxide (MgO), soda ash (Na2CO3), caustic (NaOH), and hydrochloric acid (HCl). Minor amounts of coagulant and polymer are used to aid in solid separation.

The above-mentioned equipment and systems are conventionally situated in a large, centrally-located facility that can produce steam for use at various nearby injection wells in the target reservoir. Some current conventional thermal recovery operations are accordingly designed based on the concept of a central processing facility (“CPF”) and a plurality of dispersed well pads. As can be seen in FIG. 1, the CPF-pad arrangement 1 comprises a CPF 2 and well pads 3 a, 3 b, 3 c that are distributed at some appropriate and functional distance from the CPF 2, and are in communication with the CPF 2 by means of various pipelines 4 that transport materials between each well pad 3 and the CPF 2. By distributing the well pads around and at a distance from the CPF, the idea is that the reservoir can be exploited with a complex central facility (the CPF) but relatively simple and easy-to-construct well pads at various points above the reservoir that can be serviced from the central facility.

Each well pad in such a conventional arrangement essentially functions to inject steam downhole, and to recover produced materials and pipe them to the CPF for processing. Turning to FIG. 2, the CPF 2 and pad 3 are again seen connected by pipes 4. Such pipes 4 conventionally include a produced materials pipe 5 for sending produced materials (generally bitumen, gas, water and solids) from the pad 3 to the CPF 2 for processing as described above. Also, the CPF 2 feeds various inputs to the pad 3, such as a steam supply through a high pressure steam pipe 6. Other inputs may also need to be supplied from the CPF to the well pad, as is known to those skilled in the art.

However, the requirement for the supply of steam from the CPF to each of the well pads introduces a high-pressure pipeline environment. That being the case, certain civil structural works are required, such as above-ground racks and expansion loops for the pipes. In addition, constructing a very large central facility in a mega project fashion introduces enhanced costs and execution risks, both in terms of construction and operation. Smaller and more modular equipment would facilitate more rapid installation and execution. Focusing most of the processing equipment in one relatively large CPF can negatively impact the ability to effectively exploit the reservoir.

It would therefore be desirable to have an arrangement that addresses the issues arising from constructing a large CPF to process the materials coming from the wells and generating steam while retaining the benefits of the distributed well pad system.

BRIEF SUMMARY

The present invention therefore seeks to provide a novel CPF-pad arrangement that locates certain equipment and produced materials treatment at the pads themselves, including the generation of steam at each pad for injection and thus avoiding the need for steam piping from the CPF. As the high-pressure steam pipeline environment is avoided, pipes between the CPF and well pads will be reduced in number and can be buried.

According to a first aspect of the present invention there is provided a method for generating steam for use in a subsurface hydrocarbon recovery operation, the operation comprising a central processing facility in fluid communication with at least one well pad, the well pad for servicing a related hydrocarbon recovery well, the method comprising the steps of:

locating produced materials treatment means and steam generation means at the well pad; producing produced materials from the related hydrocarbon recovery well at the well pad; treating the produced materials at the well pad to separate water and hydrocarbon from the produced materials; transporting the hydrocarbon from the well pad to the central processing facility; feeding the water to the steam generation means to generate steam; and injecting the steam into the related hydrocarbon recovery well.

In some exemplary embodiments of the first aspect of the present invention, gas is separated from the produced materials and treated using gas treatment means located on the well pad, for example for sulphur removal, before piping the gas for re-use as fuel.

In some exemplary embodiments of the first aspect of the present invention, the hydrocarbon separated from the produced materials can be subjected to partial upgrading on the well pad before being transported to the central processing facility, thus avoiding or reducing the need for diluent to enable pipelining of the hydrocarbon. Alternatively, the hydrocarbon can be subjected to partial upgrading at the CPF.

According to a second aspect of the present invention there is provided a system for generating steam for use in subsurface hydrocarbon recovery, the system comprising:

a central processing facility; at least one well pad in fluid communication with the central processing facility; each well pad adjacent a related hydrocarbon recovery well(s), the related hydrocarbon recovery well(s) for producing produced materials; produced materials treatment means at the well pad for separating gas, solids, water and hydrocarbon from the produced materials; pipeline means for transporting the hydrocarbon from the well pad to the central processing facility; steam generation means at the well pad for generating steam from the water; and steam injection means for injecting the steam into the related hydrocarbon recovery well.

In some exemplary embodiments of the second aspect of the present invention, the produced materials treatment means at the well pad is used for separating water, gas, solids, and hydrocarbon from the produced materials. The system may further comprise gas treatment means at the well pad for treating gas separated from the produced materials, for example for sulphur removal, before piping the gas for re-use as fuel.

In some exemplary embodiments of the second aspect of the present invention, the system further comprises a partial upgrading plant at the well pad for partially upgrading the hydrocarbon separated from the produced materials before being transported to the central processing facility, thus avoiding or reducing the need for diluent to enable pipelining of the hydrocarbon. Alternatively, the hydrocarbon can be subjected to partial upgrading at the CPF.

A detailed description of exemplary embodiments of the present invention is given in the following. It is to be understood, however, that the invention is not to be construed as being limited to these embodiments.

BRIEF DESCRIPTION OF THE DRAWINGS

In the accompanying drawings, which illustrate exemplary embodiments of the present invention:

FIG. 1 is a simplified view of a conventional prior art arrangement of a central processing facility and a plurality of well pads;

FIG. 2 is a simplified view of conventional piping of materials between a well pad and a central processing facility;

FIG. 3 is a simplified schematic view of a first exemplary system in accordance with the present invention; and

FIG. 4 is a simplified schematic view of a second exemplary system in accordance with the present invention.

Exemplary embodiments of the present invention will now be described with reference to the accompanying drawings.

DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS

Turning now to FIGS. 3 and 4, exemplary embodiments of the present invention are illustrated. The exemplary embodiments are presented for the purpose of illustrating the principles of the present invention, and are not intended to be limiting in any way.

FIG. 3 illustrates a first exemplary embodiment of the present invention. A single well pad 10 is illustrated as being in fluid communication with a CPF (not shown), but it is to be understood that in most cases a plurality of well pads 10 would be in communication with a single CPF. The well pad 10 comprises a separator 12 and a steam generator 14.

While FIG. 3 shows the separator 12 as a single unit, it will be clear to those skilled in the art that this would normally represent a number of discrete cooperating pieces of equipment, establishing oil removal and water treatment systems. For example, separator 12 can represent a conventional combination of a FWKO, skim tanks, induced gas flotation, WLS and WACS units. A flash-treater could also be employed. Although many different types of separation technologies could be used with the present invention as would be clear to those skilled in the art, it is preferred that the separator 12 comprise compact and modular units such as hydrocyclones, centrifuges and membrane systems, although the separator 12 need not be limited to either of these technologies.

The function of separator 12 is to take produced material and separate it into various desired components. The produced material is normally a mixture of water and hydrocarbon (in an emulsion), gas and solids, drawn from the well through line 16 to the separator 12 intake. The separator 12—through whatever process is inherent in the particular type of separator selected—separates the produced material into four streams: gas, solids, hydrocarbon and de-oiled water—the latter intended for use in steam production. The solids stream passes through line 18 to a landfill or other storage means familiar to those of skill in the art. The gas stream can be treated on the well pad 10, for example if it contains H₂S, and combusted in the steam generator 14.

The separator 12 also produces a hydrocarbon output 22, which may be a heavy hydrocarbon such as bitumen. Bitumen is normally too heavy to transport by pipeline and it is therefore common to dilute it with a diluent, conventionally a lighter hydrocarbon, to make it amenable to transport to the CPF for further processing. As can be seen in the embodiment of FIG. 3, a diluent 32 is piped in from the CPF or from a diluent line and injected into the hydrocarbon output line 22 to enable piping to the CPF; however, the use of diluent can be avoided if hot bitumen is pipelined, and diluent should therefore be viewed as optional. Other additives such as drag reduction additives are also known to those skilled in the art, and may be considered for use with this exemplary embodiment, and would be added using a line such as the chemical line 34.

In addition, chemicals such as a demulsifier may need to be sourced (from the CPF via pipeline or by tanker) to enable the desired separation of the produced material. The introduction of such chemicals is illustrated as line 34 entering the separator 12.

The final component of the produced material separated by the separator 12 is the water output 24. As discussed above, there are existing technologies that can be used to generate water of sufficient purity to be used as boiler feedstock, and the particular separation technology must be selected to match the specification needs of the steam generation technology, which is within the knowledge of the skilled person. The water output 24 from the separator 12 is then fed into the steam generator 14, producing steam 26; solids 28 and waste water (or boiler blowdown) 30 would commonly also be produced depending on the steam generation technology employed. Any solids 28 and waste water 30 would be disposed of in accordance with common knowledge in the field and applicable laws. The steam 26 is injected back into the well (not shown) to enable continued production of hydrocarbons as part of the thermal recovery operation.

Turning now to FIG. 4, an alternative embodiment of the present invention is illustrated. While similar in most respects to the method illustrated in FIG. 3 and as described above, the alternative embodiment instead seeks to partially upgrade the separated hydrocarbon stream output from the separator 12. In this embodiment, the hydrocarbon stream is directed to a partial upgrading plant (“PUP”) 36, in which the hydrocarbon is made lighter and more amenable to pipeline transport to the CPF. The partially upgraded hydrocarbon stream 38 is output from the PUP 36 and pipelined to the CPF for further processing. In this embodiment, then, there is potentially less need for a diluent stream from the CPF, although some diluent addition as illustrated in FIG. 3 may still be required. The operation of a PUP is within the knowledge of the skilled person and will therefore not be described further herein.

As can be readily seen, then, there are numerous advantages provided by the present invention. With the elimination of high-pressure steam pipes, pipelines can be buried between the CPF and the well pads, reducing the need for above-ground civil works, and on-pad steam generation can reduce the risk of steam loss and the need for pipe insulation. The total area of the CPF itself can be reduced, possibly by as much as 50% to 75%. Also, as equipment is sized for a single well pad, project execution costs and risks can be minimized in many situations.

The foregoing is considered as illustrative only of the principles of the invention. Thus, while certain aspects and embodiments of the invention have been described, these have been presented by way of example only and are not intended to limit the scope of the invention. The scope of the claims should not be limited by the exemplary embodiments set forth in the foregoing, but should be given the broadest interpretation consistent with the specification as a whole. 

What is claimed is:
 1. A method for separating water from materials produced from a subsurface hydrocarbon recovery operation, wherein the operation comprises a central processing facility in fluid communication with at least one well pad, the at least one well pad for servicing at least one related hydrocarbon recovery well, the method comprising the steps of: locating produced materials treatment means at the at least one well pad; producing produced materials from the at least one related hydrocarbon recovery well at the at least one well pad; and treating the produced materials using the produced materials treatment means to separate water from the produced materials.
 2. The method of claim 1 further comprising the step of treating the produced materials using the produced materials treatment means to separate gas and/or solids and/or hydrocarbon from the produced materials.
 3. The method of claim 2, wherein the hydrocarbon is separated, further comprising the step of transporting the hydrocarbon from the at least one well pad to the central processing facility.
 4. The method of claim 3 further comprising the step of partially upgrading the hydrocarbon at the at least one well pad before transporting the hydrocarbon to the central processing facility.
 5. The method of claim 2, wherein the gas is separated, further comprising the step of treating the gas at the at least one well pad by using gas treating means located at the at least one well pad.
 6. The method of claim 5 wherein treating the gas comprises reducing sulphur content of the gas.
 7. The method of claim 2, wherein the hydrocarbon is separated, further comprising the step of diluting the hydrocarbon with a diluent at the at least one well pad before transporting the hydrocarbon to the central processing facility.
 8. The method of claim 1 further comprising the step of demulsifying the produced materials with a demulsifier to enable separation of the produced materials.
 9. The method of claim 1 further comprising the steps of feeding the water to steam generation means located at the at least one well pad and generating steam from the water.
 10. The method of claim 9 further comprising the step of injecting the steam into the at least one related hydrocarbon recovery well.
 11. A method for generating steam for use in a subsurface hydrocarbon recovery operation, wherein the operation comprises a central processing facility in fluid communication with at least one well pad, the at least one well pad for servicing at least one related hydrocarbon recovery well, the method comprising the steps of: locating produced materials treatment means and steam generation means at the at least one well pad; producing produced materials from the at least one related hydrocarbon recovery well at the at least one well pad; treating the produced materials using the produced materials treatment means to separate water from the produced materials; feeding the water to the steam generation means to generate steam from the water; and injecting the steam into the at least one related hydrocarbon recovery well.
 12. The method of claim 11 further comprising the step of treating the produced materials using the produced materials treatment means to separate gas and/or solids and/or hydrocarbon from the produced materials.
 13. The method of claim 12, wherein the hydrocarbon is separated, further comprising the step of transporting the hydrocarbon from the at least one well pad to the central processing facility.
 14. The method of claim 13, further comprising the step of partially upgrading the hydrocarbon at the at least one well pad before transporting the hydrocarbon to the central processing facility.
 15. The method of claim 12, wherein the gas is separated, further comprising the step of treating the gas at the at least one well pad by using gas treating means located at the at least one well pad.
 16. The method of claim 15 wherein treating the gas comprises reducing sulphur content of the gas.
 17. The method of claim 13, further comprising the step of diluting the hydrocarbon with a diluent at the at least one well pad before transporting the hydrocarbon to the central processing facility.
 18. The method of claim 11 further comprising the step of demulsifying the produced materials with a demulsifier to enable separation of the produced materials.
 19. A system for steam generation for use in subsurface hydrocarbon recovery, the system comprising: a central processing facility; at least one well pad in fluid communication with the central processing facility, wherein the at least one well pad is adjacent to at least one related hydrocarbon recovery well, the at least one related hydrocarbon recovery well for producing produced materials; produced materials treatment means at the at least one well pad configured to separate water from the produced materials produced from the at least one hydrocarbon recovery well; steam generation means at the at least one well pad for receiving the water and generating steam from the water; and steam injection means for injecting the steam into the at least one related hydrocarbon recovery well.
 20. The system of claim 19 wherein the produced materials treatment means are configured to separate gas and/or solids and/or hydrocarbon from the produced materials.
 21. The system of claim 20 wherein the produced materials treatment means are configured to separate the hydrocarbon from the produced materials, further comprising pipeline means for transporting the hydrocarbon from the at least one well pad to the central processing facility.
 22. The system of claim 21 further comprising an upgrading plant at the at least one well pad for partially upgrading the hydrocarbon before transporting the hydrocarbon to the central processing facility.
 23. The system of claim 20 wherein the produced materials treatment means are configured to separate gas from the produced materials, further comprising gas treating means located at the at the least one well pad for treating the gas at the at least one well pad.
 24. The system of claim 23 wherein the gas treating means are for reducing sulphur content of the gas.
 25. The system of claim 21 further comprising a diluent source for diluting the hydrocarbon with a diluent at the at least one well pad before transporting the hydrocarbon to the central processing facility.
 26. The system of claim 19 further comprising a demulsifier source for providing demulsifier to the produced materials to enable separation of the produced materials. 